P-164
Knowing a Giant Gas Reservoir with Time
K K Roy*, Dr R V Marathe, P P Deo, S K Pant, K N Jha,, ONGC
Summary
Field development of Giant gas reservoirs unlike oil reservoirs is typified with market linked necessities coupled with a
compulsory plateau period. Techno-economics of gas reservoirs thus invariably take into cognizance the gas quality/
quantity/ input-pressure needs of the user industry along with delivery commitment period and profitability. Giants are thus
developed with care and caution, as fall back for committed sales is rare and mid-course corrections are limited. Initial field
development based on the delineation wells fall short in the desired level of characterization and absence of pressure production history with time limits understanding from reservoir engineering perspective. Knowing the reservoir with time is
thus the key and phase development the solution, but integrating the same in the business model is the challenge.
The learning curve generated with time for the giant offshore gas field ‘Bassein’ in the Western Offshore Basin of Ind ia
and its effective use in field development in phases ensuring uninterrupted gas supply in accordance with commitments for
the last three decades demonstrates the worthiness of the concept. This paper attempts to explain how the concepts
pertaining to the geological understanding had to be continuously refined with new sets of data generated and exploitation
strategies revised infusing techno-economically acceptable investment to be consistent with the production commitments.
The changes in understanding are often radical but given the consequent implications thereof, are convincingly supported by
well data/observations. The paper emphasizes, that the perceived development challenges at the appraisal stage are not
necessarily the ones that have a considerable bearing in the final stages of field d evelopment. The need is thus to have a
robust but balanced development plan ensuring operational easiness adequate to accommodate surprises rather than one
based on perceived but not so critical issues. The field discussed herein being in reality an oil reservoir of 850+ MMbbl
with large (high m value) rich gas cap, complex decision making process are obvious but a combination of market needs operational easiness-risk mitigations- profitability led to a pragmatic solution search that paid rich dividends both in short
and long term.
Keywords: Field Development, FZI, Dynamic Modelling
Introduction
The giant Bassein field in the continental shelf of Arabian
sea in the West coast of India at an average water depth of
50m established oil and gas in Mid Eocene and Lower
Oligocene limestone through the discovery well SB-1 in the
mid-seventies. Subsequent delineation through seven
exploratory wells defined the reservoir to be an oil
reservoir overlain by a large gas cap with „m‟ of about 10
and underlain by a mild aquifer.
On the basis of lithology, age and regional correlation of
Bombay Offshore Basin this large limestone reservoir of
about 450 m is sub-divided into „Bassein‟ Zone of Middle
Eocene age , „Mukta‟ Zone of Lower Oligocene age and
the intervening „Tight zone‟ of Lower Oligocene age.
Being a saturated reservoir with about 90 m of gas column,
10-12 m of oil column and about 320 m of underlying
aquifer, exploitation strategy at the concept level is the key
issue considering the high reward in producing rich gas with
substantial derivatives in sharp contrast with the associated
difficulty in terms of water/ gas coning while producing rim
oil. The volumetric estimates on a simplistic hydrocarbon
map based on the delineation/ discovery wells could see
„Mukta‟ Zone hosting about 42 BCM of gas while the
underlain „Bassein‟ Zone holds around 288 BCM of Gas
Cap Gas (GCG) & 116 MMT of rim oil.
Room No.232, Institute of Reservoir Studies, Oil and Natural Gas Corporation Limited,
Chandkheda Campus, Ahmedabad-380005.
e-mail:[email protected]
Knowing a Giant Gas Reservoir with Time
The initial dilemma
The discovery and the quantum of oil inplace volumes
generated considerable interest in the field. However, it was
soon realised that the exploitation of such an oil
accumulation is likely to pose serious operational problems
due to gas and water coning restricting oil production
through the critical rates. Coning studies in wells SB-4, 7
indicated that a rate of 10 m3/d to 60 m3/d is achievable
only for the first couple of years. Similar studies carried out
indicated that the local water coning and edge water
encroachment effect would be dominant constraint in
techno-economically acceptable field development
planning. In view of the above, it was felt prudent to go for
gas exploitation in the beginning given the high gas cap gas
inplace, attractive well deliverability capable of both ROI of
high capex and marketing potential needs in the Western
part of India, till tailor made technological solutions for
exploitation of thin oil column is in place.
Production Performance
The field was put on commercial production from
September 1988, gas being the targeted deliverable.
Subsequent development campaign based on studies with
additional drilling data and pressure-production history at
different point in time was initiated to enhance production,
optimizing drainage across the geographical spread. The
philosophy of „learn-unlearn-develop‟ was centric to these
campaigns and thus investment for development was in
several phases, each phase dovetailing the renewed
understanding of the earlier. The historical field
performance till March 31, 2011 is placed as Figure-1. It
achieved a peak production rate of 32 MMSCMD in 20012002. The average production rate during 2009-2010 &
2010-2011 is about 28 MMSCMD respectively. The
cumulative production from the field by March 31, 2011 is
around 199 BCM and the average field pressure has
declined from initial value of 178 kg/cm2 to around 100
kg/cm2 against this production. Currently gas is being
exploited through 49 wells spread over 6 platforms with
additional 4 horizontal wells targeting the underlain oil rim.
Figure-1: Production Performance of Bassein
Phases of Field Development:
The field has so far undergone 5 major Phases of
development. In the first phase two well platforms namely
BA and BD and one process platform BPA (capacity 10
MMSCMD) was put in place during 1988-1989. A 36”
offshore to onshore Trunk Line was also commissioned
during this phase and the field was geared to meet a
production of 10 MMSCMD. In the second phase of
development two well head platforms namely BB & BC
and a process complex BPB (capacity 10 MMSCMD) were
installed in 1989. The field was now geared to produce 20
MMSCMD of gas. The steady performance of the field
from the northern four platforms brought in third phase
which targeted the southern portion of the field by bringing
BE platform. The processing capacities of the two process
complexes were raised to 12.5 MMSCMD each. Another
important aspect of the third phase was commissioning of
42” Trunk line to meet future production level of 30
Mmm3/d. Sustained production led to continued drop in
reservoir pressure and it was realised that booster
compressor will be a technical necessity to maintain
requisite pressure in order to transport required quantity of
gas. Under the fourth phase (1999) two booster
compressors were installed at BPA & BPB. The production
peaked at 32 MMSCMD in 2002. The fifth and final phase
was focussed at further development of southern portion of
the field by bringing BF platform in 2008. A second stage
booster compressor was installed in BPA & BPB during
this phase.
History of Inplace Assessments
The revisions of the inplace were necessitated due to
improved performance of the field as indicated in Figure-2.
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Knowing a Giant Gas Reservoir with Time
The concomitant pressure drop in the field being less than
anticipated from purely depletion drive estimates was
suggestive of static model revisits necessity. Several
possibilities that could lead to restriction of pressure
decline were explored and examined for mathematical and
geological acceptability. This included analysis of pressureproduction history, seismic and drilled data combine
revisits. The last revision was necessitated in 2010 post
commissioning of BF platform as well BF-1 (southern part
of the field) recorded a pressure of 129 kg/cm2 much higher
than the pressures in the northern part of the field (105
kg/cm2). In the meantime satellite discoveries with different
contacts and depleted pressures both in the west and east led
to the belief of some pressure support possibly transmitted
through the underlain connected aquifer.
character of TZ. Revisits of open hole logs of TZ, CBLVDL, RFT and test data of wells is suggestive of Mukta and
Bassein formation to be in locality specific communication,
reasoning being downward flow of hydrocarbons through
channels and porous chimneys. The RFT pressure of
exploratory well SB-10 (February 2001) against Mukta
formation shows a decline in pressure to the tune of 160
kg/cm2 from initial value of 178 kg/cm2. This is not
commensurate with a meagre reported production of 0.323
BCM (<1% of estimated inplace) from Mukta through a
couple of wells. The RFT record of SB-10 placed in
Figure-3 exhibits the pressure below -1651 mMSL
dropping below 152 kg/cm2 and this is an indication of
Figure-3: Pressure vs. Depth of Mukta
Figure-2: Performance: Plan vs. Actual
The GIIP revision at different time steps with squaring up
efforts of Material Balance and renewed G&G
understanding is tabulated below.
Year
2004
2007
2009
2010
Mukta
(BCM)
34
34
41
41
Bassein
(BCM)
239
268
268
288
Total
(BCM)
273
302
310
330
The connectivity between Mukta and Bassein pays
possible communication. RFT pressure of well BSE-1 in the
adjoining satellite discovery in August 1997 also exhibit
lowering of pressure (163 kg/cm2) at Mukta level. A plot of
RFT pressure and cumulative production vs. time plotted in
Figure-4 indicates that A Zone pressure start to decline
after 1995 though there was no significant production from
Mukta formation during this time. It is worth mentioning
that the SBHP recorded in January 2009 in well BE-7Z
which is, currently the only well producing from Mukta
formation indicates a pressure of 115 kg/cm2. MDT of
recently drilled exploratory well SBJ also shows a pressure
of 105 kg/cm2 at Mukta level. In light of the above data, it is
now comprehensively believed Mukta & Bassein to be in
communication and that Mukta is participating towards
production through the TZ and accordingly modelled.
The tight zone (TZ) separating Mukta and Bassein
formation traditionally has been considered to be some kind
of barrier allowing very restricted communication between
the zones. This negated the possibility of pressure support
from Mukta formation and any kind of participation in
production. This, therefore, necessitated a relook into the
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Knowing a Giant Gas Reservoir with Time
Figure-4: Variation in Mukta Pressures with Time
An exhaustive study of the isolation between zones based
on CBL-VDL signatures shows the following distribution.
Reservoir Characterisation through Hydraulic
Unitisation
The fundamental static property of porosity and dynamic
property of permeability are two parameters, which have
been used extensively by various authors1-5 to uniquely
characterize a reservoir through its flow units.
Amaefule et.al, 1993 has presented a simple approach
commonly known as flow zone indicator (FZI) for
quantification of rock tying. It is based on the following
equations:
The above pie chart extends the concept of gas migration
from Mukta to Bassein through channelling behind casing
phenomenon and since 20 wells (47%) have poor isolation
i.e. BA-1,2,5,6; BB-4,5,7,8,9; BD-2,3,4,5,6 and BE-2,5,8,9.
Mukta production is understandably in vogue from almost
all platforms.
The development of porosity and HC accumulation along
North-South direction is depicted below through wells BD2, 4, 5; BA-4; BB-6, 9 & BE-3.It is also interesting to note
that these wells are distributed throughout the field.
Where
RQI : reservoir quality index,
k : permeability (md),
Øe : effective porosity (fraction),
Øz : Normalised Porosity
FZI: Flow zone indicator
Both SB#4 and SB#7 are having continuous core of length
40 and 80 m respectively against Bassein section. This has
provided an exhaustive core property data base of 140 and
251 core plugs in SB#4 and SB#7. These porosity and
permeability data have been used and 6 hydraulic units
have been identified by using equations1 to 3 and have been
presented in Figure-5 to 7.
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Knowing a Giant Gas Reservoir with Time
Figure-5:Porosity Permeability distribution
Figure-8:k-phi transform for HU2+HU3
Figure-6: Rock Quality Index
Figure-9
There is very good match between these derived K-Φ
transforms and the transform which were used in the earlier
phases and was an integral part of the initial FDR on
Bassein.
Dynamic modeling
Figure-7:Hydraulic Units-Bassein formation
The Hydraulic Unitisation distinctly indicates that units
HU-2 and HU-3 together constitute hydraulic units which
contain the major part of the sample population. The data of
these two units have been further analysed to arrive at
distinctive K-Φ relationship. This data cluster have been
further subdivided in to two groups: Φ<0.24 and Φ>0.24.
The curve fit analysis is shown in Figure-8 and Figure-9
respectively.
Having recovered almost 57% of in place gas, the final
development of Bassein is round the corner. The dynamic
simulation thus for the first time is through a giant
integrated model encompassing Mukta-Bassein production,
Mukta-Bassein connectivity, and modelled ongoing
production impact of satellite fields for pressure
transmissibility through
aquifer connectivity. The
geocellular static model (2.4 million cells) was devoid of
any upscaling to avoid losing of any characterization and
event mapping. Given that Water and pressures to be the
key prediction parameters deterministic of additional
investment, history matching both at well/platform and
field level has been done with utmost care. Study indicates
possibility of cumulatively producing around 79 & 81% by
year 2023 under „business as usual‟ and „additional
development‟ cases respectively.
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Knowing a Giant Gas Reservoir with Time
Conclusions
References

Leverett, M.C.: “Capillary behaviour in porous solids”
Petroleum Transactions of AIME (1941) 142, pp 152169.

Deliverables of Gas giants need to be strategized in
micro-detail as surprises in adversity are in for market
turbulence from the recipient side. The phased
development approach of Bassein field which is based
on the philosophy of learn-unlearn and develop has
put in place a robust infrastructure capable of
realizing
the field potential effectively with all
possible value added products.
Ample evidences with time suggest communication
between Mukta and Bassein formation, nullifying the
age old apprehension that Mukta will be near virgin at
the end life of Bassein and Bassein wells can be
transferred to Mukta. Capability of Mukta to deliver
obviated the need for conscious monetization
attempts with high level of confidence in the
final phase of development.

The FZI approach brings out two dominant
hydraulic flow units and robust k-phi transform could
be generated for each of these units.

Dynamic model in the last phase is able to capture all
associated events and history not only in the main
field but also the hydrocarbon withdrawal effects in
the satellite discoveries understandably connected
through aquifer. Modelling approach to capture effects
of hydrocarbon production from neighbouring fields
has its own uniqueness and the fact that it could be
effectively history matched spells out the robustness of
the model. This was possible because the knowledge
of the reservoir matured with time and was adequate to
capture unknowns effectively with plausible
implications.

The field in terms of enhancing significant
recoveries do not show promise-a key indicator of
earlier strategies to be reasonably non-destructive. But
accelerating and/or preponing recoveries with
additional investment has ample merits and reasoning
to be an inclusive part in the field of Bassein hopefully
the last phase till abandonement.
Amaefule, J.O., Altunbay, M., Tiab, D., Kersey,
D.G., Keelan, and D.K.: “Enhanced reservoir description:
using core and log data to identify hydraulic (flow) units
and predict permeability in uncored intervals/wells,” paper
SPE 26436 presented at the 1993 Annual Technical
Conference and Exhibition, Houston, Texas,Oct. 3-6.
Amaefule, J.O., Altunbay, M., Tiab, D., Kersey,
D.G., Keelan,and D.K.: “Enhanced reservoir description:
using core and logdata to identify hydraulic (flow) units and
predict permeability in uncored intervals/wells,” paper SPE
26436 presented at the 1993Annual Technical Conference
and Exhibition, Houston, Texas,Oct. 3-6.
Barr, D.C. and Altunbay, M.: “Identifying hydraulic
units as an aid to quantifying depositional environments
and diagenetic facies,” paper presented at the 1992 Geology
of Malaysia, Symposium on Reservoir Evaluation /
Formation Damage, Kuala Lumpur, Malaysia, July 11.
Biniwale, S. and Behrenbruch, P.: “An Improved
Approach for Modelling Geological Depositional
Characteristics and Fluid Saturation
by Using Hydraulic
Units: Australian Offshore Fields.” presented at the 2005
46th Annual SPWLA Meeting, New Orleans, USA,
June 26-29.
Acknowledgments
The authors are grateful to Oil and Natural Gas Corporation
Limited (ONGC), India for providing the opportunity to
carry out the work and permitting them to publish the
paper. The authors also wish to acknowledge the free use of
the basic data generated at different work centers of ONGC.
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